The invention relates to detection of subsurface hydrocarbons. More particularly, the invention relates to an improved method and apparatus for locating strata that contain natural gas in paying quantities.
In the field of hydrocarbon exploration, the earliest uses of seismic data focused on mapping the structural position of subsurface formations based on the two-way travel time of seismic signals that reflect off underground rock layers. With refinement of seismic exploration methods, interpreters noted a correlation between certain characteristics of the seismic signal and the presence of hydrocarbons in the subsurface. This approach to interpreting seismic data generally is called "direct hydrocarbon indication," and focuses on how the presence of hydrocarbons, especially natural gas, affects the amplitude, frequency, phase and other dynamic characteristics of the seismic signal.
The most widely used direct hydrocarbon indication analysis focuses on the amplitudes of return signals. Natural gas reservoirs can generate a large reflected signal, known as a "bright spot" on the seismic line. Reflections occur when compression waves pass from one medium into a second medium with different physical characteristics such as density and the velocity at which sonic waves propagate through the medium. However, bright spot analysis is an imperfect means of detecting gas because bright spots are not necessarily indicative of a gas field, but also can result from adjacent strata with sufficiently different physical characteristics.
One approach that improves on the basic bright spot search technique is called Amplitude Versus Offset (AVO). The subject of a 1984 article by Ostrander entitled "Plane-wave reflection coefficients for gas sounds at non-normal angles of incidence," 49 Geophysics, 1637, (1984), this approach capitalizes on the phenomenon that gas-bearing strata generate a reflection whose amplitude varies according to the angle of incidence of the incoming waveform. In contrast, bright spots generated at the interface of two incompressible substances, such as a stratum of light rock that overlays a stratum of dense rock, show little amplitude variance as the incidence angle changes. To differentiate the two types of bright spots, the geophysicist need only vary his source and receiver positions so as to bounce seismic waves off the same stratum from a variety of angles, and inspect the reflected signals for a strong amplitude change as a function of the angle.
A second approach to direct hydrocarbon indication is to analyze the frequency content of the seismic signal. The presence of natural gas affects the frequency content of the seismic wave by increasing the rate of energy absorption as a function of increasing frequency. Direct hydrocarbon indication techniques that use frequency analysis focus on two areas: (1) detecting anomalous rates of energy decay in the seismic waveform (the "inverse Q method"), and (2) detecting a downshift in the dominant frequency that is commonly associated with natural gas deposits. Frequency analysis is particularly effective when used in conjunction with other approaches that interpret the amplitude of the returned waveform over time, namely, bright spot and AVO techniques.
Phase response is a third characteristic of the seismic waveform that has been used as a direct hydrocarbon indicator. In many cases, a gas accumulation in a subsurface stratum will cause a phase reversal between signals in a stacked seismic array. This approach is particularly useful where a porous stratum runs at an angle to horizontal, causing a lower portion of the stratum to be brine-filled and a higher portion to be gas-filled.
These conventional technologies have certain limitations in practice. Depth is a primary constraint. The AVO technique becomes increasingly unreliable at greater depths because, as a matter of geometry, the source and receiver must be placed further apart to obtain the required angle of incidence and reflection. Depth also creates serious problems with the inverse Q method. High frequency signals are attenuated more rapidly than lower frequencies, even when propagating through non-gas-bearing media. At increasing depth, the cumulative attenuation of energy levels at the high-frequency end of the spectrum makes detection of anomalous energy absorption unreliable.
In addition to these depth-related problems, the direct hydrocarbon indication techniques described above are problematic in that they do not discriminate well between high and low levels of gas saturation. Gas saturation, which is a measure of the volume of gas versus the volume of rock matrix plus other fluids, is a fundamental variable for determining the potential recovery of hydrocarbon from subsurface reservoirs. Both the seismic energy attenuation and seismic amplitude detection methods attain anomalous response levels at a relatively low gas saturation. Therefore, These techniques cannot provide an accurate indicator of gas saturation.